Tight Gas Sands Research Articles

Basin-centred gas in the Makó Trough, Hungary: a 3D basin and petroleum system modelling investigation

ABSTRACT World-wide exploration for unconventional hydrocarbon accumulations has been increasing in the last decade. The deep Mako Trough of the Pannonian Basin in southeast Hungary has become a new target for companies looking for unconventional gas resources, but so far the exploration drilling has been unsuccessful. To investigate the size of the assumed basin-centred gas accumulation we have studied the hydrocarbon potential of the source rocks in the Mako Trough using 3D basin and petroleum system modelling technology. The thermal and maturity history and timing of hydrocarbon generation were assessed, and the generated volume of hydrocarbons estimated and compared with the pore volume of the assumed unconventional reservoirs. The estimated mean volume of gas generated in the drainage area (490–650 × 10 9 Sm 3 ) [given at surface conditions] is much less than the volume (>14 × 10 12 Sm 3 ) needed to fill the basin-centred gas accumulation. Therefore, the Mako Trough is unlikely to contain a large tight-gas sand accumulation. The Endrőd Marl is a fair quality, gas-prone source rock with average original TOC values of 0.75 wt%, reaching 1.5 wt% in the Hod-I and Mako-7 wells. These are below the TOC values of the proven gas shales of North America.

Current Situation of Tight Sand Gas in China

Unconventional natural gas because of a huge amount of resources has been received extensive attention in the world. Based on the present technology in China, tight sand gas as one type of unconventional gas, has become the most realistic energy resources, and has reached a certain development scale. Low porosity and permeability of tight sand gas reservoirs are widely distributed in China's major basins, the proved reserves of tight sand gas reservoirs in the proportion of reserves increases significantly year by year. Tight sand gas exploration in unconventional natural gas is most realistic, the concept of tight sand gas, reservoir characteristics, formation mechanism of unconventional tight sand gas, distribution in China are reviewed in the essay, exploration direction and some suggestions are pointed out at the end.

Recognition of Fracturing by Stimulated Reservoir Volume (SRV) in Shale Gas Wells

Ultra-low permeability shale reservoir require a large fracture network to maximal well performance. In conventional reservoirs and tight gas sands, single fracture length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex fracture network are created, single fracture length and conductivity are insufficient to stimulate. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. This paper mainly illustrates perforation with interlaced row well pattern and multi-fracture fracturing technology and refracturing applied in vertical wells. Moreover, it establishes the seepage differential equation of multi-fracture.

Measuring low permeabilities of gas-sands and shales using a pressure transmission technique

Liquid and gas permeability measurements for tight gas-sand and shales were done using a pressure transmission technique in specially designed apparatus in which confining pressure, pore pressure, and temperature are independently controlled. Downstream pressure changes were measured after increasing and maintaining upstream pressure constant. The initial pressure difference changes only after the pressure pulse propagates across the sample. For low permeability samples, the downstream pressure increase is delayed but the measurement senses a greater sample volume. On the other hand, conventional pulse decay techniques provide a more rapid response but are sensitive to local sample permeability heterogeneity. Permeability measured for the rocks studied varies from 1.18×10 −15 to 3.95×10 −21 m 2. The measured permeability anisotropy ratio in gas shale varies from 20% to 31%. The magnitudes of permeability anisotropy remain almost constant, but the absolute permeability values decrease by a factor of 10 with a 29.79 MPa effective pressure. All samples showed a nonlinear reduction in permeability with increasing effective pressure. The rate of reduction is markedly different from sample to sample and with flow direction. This reduction can be described by a cubic k– σ law and explained by preferential flow through microcracks.

Pore-throat sizes in sandstones, tight sandstones, and shales: Discussion

Wayne K. Camp Nelson (2009) prepared a nice compilation describing the wide range of pore-throat sizes that span a continuum from conventional sandstone reservoirs to unconventional tight-gas siliciclastic reservoirs and shale seals. In this article, Nelson (2009) proposes a new and rather unique definition for unconventional reservoirs (including tight-gas sands) that lacks sufficient supporting evidence or references to support this definition. Nelson (2009, p. 329) defines a conventional reservoir as, “…one in which evidence that buoyant force has formed and maintained the disposition of oil and gas is present,” and thus for unconventional reservoirs, it follows that Nelson concludes (p. 330) that, “In these systems, evidence for buoyancy as a dominant force in the disposition of oil and gas is lacking.” It appears that the sole argument for nonbuoyant or buoyancy-subordinate unconventional reservoir systems is the perceived lack of evidence of buoyancy, which is generally not good science (absence of evidence is not evidence of absence). It would be much better to present a clear and concise hypothesis followed by objective observations that support the conclusions. I appreciate that such a thesis may be beyond the scope of a Geologic Note article, but until such evidence is presented, it is difficult to have intelligent discussions and design experiments to test the hypothesis of nonbuoyant gas systems. Although it is not clear from the definition of Nelson (2009), the reader is left to conclude that the natural laws of buoyancy are not dominant factors during the evolution of tight-gas sand accumulations from hydrocarbon migration to the present-day observed distribution of hydrocarbons and water. This conclusion is misleading and ignores a significant body of recent published research (Shanley et al., 2004; Cluff et al., 2005; Fassett and Boyce, 2005; Camp, 2008). Nelson (2009, p. 339) further concludes …

Application of 3D vertical seismic profile multi‐component data to tight gas sands‡

ABSTRACTDue to the complicated geophysical character of tight gas sands in the Sulige gasfield of China, conventional surface seismic has faced great challenges in reservoir delineation. In order to improve this situation, a large‐scale 3D‐3C vertical seismic profiling (VSP) survey (more than 15 000 shots) was conducted simultaneously with 3D‐3C surface seismic data acquisition in this area in 2005. This paper presents a case study on the delineation of tight gas sands by use of multi‐component 3D VSP technology. Two imaging volumes (PP compressional wave; PSv converted wave) were generated with 3D‐3C VSP data processing. By comparison, the dominant frequencies of the 3D VSP images were 10–15 Hz higher than that of surface seismic images. Delineation of the tight gas sands is achieved by using the multi‐component information in the VSP data leading to reduce uncertainties in data interpretation. We performed a routine data interpretation on these images and developed a new attribute titled ‘Centroid Frequency Ratio of PSv and PP Waves’ for indication of the tight gas sands. The results demonstrated that the new attribute was sensitive to this type of reservoir. By combining geologic, drilling and log data, a comprehensive evaluation based on the 3D VSP data was conducted and a new well location for drilling was proposed. The major results in this paper tell us that successful application of 3D‐3C VSP technologies are only accomplished through a synthesis of many disciplines. We need detailed analysis to evaluate each step in planning, acquisition, processing and interpretation to achieve our objectives. High resolution, successful processing of multi‐component information, combination of PP and PSv volumes to extract useful attributes, receiver depth information and offset/ azimuth‐dependent anisotropy in the 3D VSP data are the major accomplishments derived from our attention to detail in the above steps.

Chemical and physical characterization of produced waters from conventional and unconventional fossil fuel resources

Characterization of produced waters (PWs) is an initial step for determining potential beneficial uses such as irrigation and surface water discharge at some sites. A meta-analysis of characteristics of five PW sources [i.e. shale gas (SGPWs), conventional natural gas (NGPWs), conventional oil (OPWs), coal-bed methane (CBMPWs), tight gas sands (TGSPWs)] was conducted from peer-reviewed literature, government or industry documents, book chapters, internet sources, analytical records from industry, and analyses of PW samples. This meta-analysis assembled a large dataset to extract information of interest such as differences and similarities in constituent and constituent concentrations across these sources of PWs. The PW data analyzed were comprised of 377 coal-bed methane, 165 oilfield, 137 tight gas sand, 4000 natural gas, and 541 shale gas records. Majority of SGPWs, NGPWs, OPWs, and TGSPWs contain chloride concentrations ranging from saline (>30000mgL−1) to hypersaline (>40000mgL−1), while most CBMPWs were fresh (<5000mgL−1). For inorganic constituents, most SGPW and NGPW iron concentrations exceeded the numeric criterion for irrigation and surface water discharge, while OPW and CBMPW iron concentrations were less than the criterion. Approximately one-fourth of the PW samples in this database are fresh and likely need minimal treatment for metal and metalloid constituents prior to use, while some PWs are brackish (5000–30000mgCl−L−1) to saline containing metals and metalloids that may require considerable treatment. Other PWs are hypersaline and produce a considerable waste stream from reverse osmosis; remediation of these waters may not be feasible. After renovation, fresh to saline PWs may be used for irrigation and replenishing surface waters.

High-resolution 3D fabric and porosity model in a tight gas sandstone reservoir:A new approach to investigate microstructures from mm- to nm-scale combining argon beam cross-sectioning and SEM imaging

The development of new technologies to enhance tight gas reservoir productivity could strongly benefit from a better resolution and imaging of the porosity. Numerous methods are available to characterize sandstone porosity. However, imaging of pore space at scales below 1 μm in tight gas sands remains difficult due to limits in resolution and sample preparation. We explored the use of high resolution SEM in combination with argon ion beam cross sectioning (BIB, Broad Ion Beam) to prepare smooth, and damage-free, true-2D surfaces of tight gas sandstone core samples from the Permian Rotliegend in Germany, to image porosity down to 10 nm. The quality of cross-sections allows measuring porosity at pore scale, and describing the bulk porosity by defining different regions with characteristic pore morphology and pore size distribution. Serial cross sectioning of samples produces a 3D model of the porous network. We present a model of fabric and porosity at 2 different scales: the scale of sand grains and the scale of the clay grains in the intergranular volume.

Hydraulic fractures productivity performance in tight gas sands—a numerical simulation approach

The increasing global demand for energy along with the reduction in conventional gas reserves has lead to the increasing demand and exploration of unconventional gas sources. Hydraulically-fractured tight gas reservoirs are one of the most common unconventional sources being produced today and look to be a regular source of gas in the future. Hydraulic fracture orientation and spacing are important factors in effective field drainage and gas recovery. This paper presents a 3D single well hydraulically fractured tight gas model created using commercial simulation software, which will be used to simulate gas production and synthetically generate welltest data. The hydraulic fractures will be simulated with varying sizes and different numbers of fractures intersecting the wellbore. The focus of the simulation runs will be on the effect of hydraulic fracture size and spacing on well productivity performance. The results obtained from the welltest simulations will be plotted and used to understand the impact on reservoir response under the different hydraulic fracturing scenarios. The outputs of the models can also be used to relate welltest response to the efficiency of hydraulic fractures and, therefore, productivity performance.

Gas saturation measurement in low-porosity sands

Traditionally, pulsed neutron data has been used to calculate water saturation and/or monitor gas/water contacts in zones of high formation water salinity. In low or unknown salinities carbon/oxygen measurements have been used for oil saturation measurements in porosities greater than 15%. In tight gas sands, porosities are typically less than 10% and are too low for either method to work. In gas sands with low or unknown water salinities and porosities below 15%, neither Sigma or C/O measurements will work. New pulsed neutron instrumentation and methodology are available for through-casing gas saturation measurements. The new technology is independent of water salinity and enables gas saturation calculations to be made in porosities as low as 5%. The technique includes modelling that enables the tool response to be determined in advance. Modelling takes into account several factors, including: lithology, completion geometry, reservoir pressure, gas density, and gas composition (for example: methane or CO2). The measurements are sensitive to gas pressure in the reservoir, and this paper will discuss ways that the data can be used to infer the relative and, in some cases, absolute pressures of different zones. The data set presented straddles the gas/water contact in the borehole. The effects of re-invasion by the borehole fluids will be discussed with respect to the corresponding openhole and cased hole water saturations, from both inelastic and capture measurements.

Complexity in tight gas sand development—an example from Perth Basin, Western Australia

One of the key issues for tight gas reservoirs is about reservoir heterogeneities and its connectivity. Knowledge of reservoir geometry, orientation, and connectedness is vital for reservoir modelling, which is the essential tool for successful field development, well completion, and well stimulation strategies. Fluvial sediments are heterogeneous both vertically and laterally due to facies change and diagenetic processes. These make their field development difficult. In terms of sand geometry and connectivity, the first step to making the reservoir model in three directions is to determine the width of sandstone bodies in various directions. Fine-grained facies associated with fluvial deposits can compartmentalise reservoirs and can significantly complicate the development of such units, as well as make well stimulation and fracturing jobs unpredictable. In this paper, the above issues are studied for some fluvial tight gas sands of the Perth Basin. The aim is to discuss the best possible way to successfully plan well and well stimulation strategies.

Sensitivity of velocities to overpressure within heterogeneous tight gas sand reservoirs

Tight gas sands account for approximately 19% of the total U.S. gas production, and may contain more than 35% of the U.S. recoverable gas resources (Oil and Gas Investor, 2005). In order to test technology for the production of gas from tight gas sands, the U.S. Department of Energy sponsored a Multiwell Experiment (MWX) in the Rulison gas field in the Piceance Basin, Colorado (Northrop et al., 1983). Drilling commenced in 1981, the field program was completed in 1988, and reporting was completed in 1990. In this article, we examine the relation between acoustic-wave velocities and pore pressures using data acquired during this experiment, and show how acoustic velocities can be used to estimate pore pressure. This is important, because pore pressure is an important factor determining the amount of gas in place, but is difficult to measure directly in low-permeability formations.

Global Unconventional Gas - It Is There, But Is It Profitable?

Management Gas reservoirs are often classified as conventional or unconventional. Conventional gas reservoirs are characterized by high permeability with the gas stored in sand or carbonate formations in pore spaces that are interconnected. A gas resource is generally considered conventional if it does not require a large stimulation treatment to be able to produce oil and gas at economic flow rates. An unconventional gas reservoir can be defined as a natural-gas reservoir that cannot be produced at economic flow rates or in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or multilateral wellbores (Holditch, 2006). The three most common types of unconventional gas resources are tight sands, coalbed methane, and gas shales. Unconventional gas reservoirs are characterized by low permeability, in the microdarcy range (Fig. 1) or less. As the permeability deceases, the economic risk of developing the resource increases, and the investment required also increases because more wells have to be drilled to produce the reservoir, as each well recovers less gas per well than one can recover per well from a conventional reservoir. The US Department of Energy’s (DOE’s) Energy Information Administration (EIA) defines the total natural-gas resource base as all of the gas that has ever been trapped inside the Earth, including the volumes that have already been produced. The part of the total natural-gas resource base that interests investors most, however, is the remaining natural gas waiting to be extracted. Research indicates the existence of large, unconventional gas reservoirs located throughout the world. Rogner (1997) estimated that there are 9,000 Tcf of original gas in place (OGIP) reserves in coalbed methane, 16,000 Tcf of OGIP in shale gas, and 7,400 Tcf of OGIP in tight gas sands around the world (Table 1). Since Rogner published his paper, the oil and gas industry has discovered enormous volumes of natural gas in unconventional gas reservoirs in North American and in several other basins around the world. It is believed that the OGIP estimates in Table 1 are very conservative. The industry will be updating the values in Table 1 and it is expected that the values of OGIP will increase substantially. With declining conventional gas reserves in the United States, unconventional gas reservoirs are emerging as critical energy sources to meet the increasing demand for energy. The US DOE April 2009 report, Modern Shale Gas Development in the United States: A Primer, stated that over the last decade, production from unconventional resources in the US has increased almost 65%, from 5.4 Tcf/yr in 1998 to 8.9 Tcf/yr in 2007. This increase in production indicates that approximately 46% of today’s US total gas production comes from unconventional resources (Navigant 2008).

Introduction to this special section: Tight gas sands

U.S. production of natural gas is expected to increase from 20 TCF/year in 2008 to approximately 23 TCF by 2035, with most of this growth projected to come from expansion of shale gas plays (Energy Information Administration, Annual Energy Outlook, 2010). The bulk of the production, however, will continue to come from sandstone reservoirs, with tight gas sandstones contributing about 19% of the total daily production (Oil and Gas Investor, 2005).

Seismic petrophysics and isotropic-anisotropic AVO methods for unconventional gas exploration

Exploration and drilling for natural gas in North America has moved radically away from conventional reservoirs to focus on unconventional reservoirs such as tight gas sands and shales. These reservoirs have low porosity and near-zero permeability with gas stored in natural fractures and within the matrix porosity. Economic gas production requires hydraulic fracture stimulation to open connections to existing natural fractures or matrix porosity, and successful stimulation depends on the formation's geomechanical brittleness being capable of supporting extensive induced fractures. However, despite adequate stimulation, significant variations exist between wells in expected ultimate recovery (EUR) due to the heterogeneity of these resource plays. Consequently, predicting natural fractures or fracture-prone “sweet spots” is essential to optimize development of such plays.

A rock physics model for tight gas sand

Tight gas reservoirs are often defined as gas-bearing sandstones or carbonates having in-situ permeabilities to gas less than 0.1 mD (Holditch, 2006; Smith et al., 2009). Tight gas reservoir rocks can be at different in-situ physical conditions: deep or shallow; over- or underpressured; high temperature or low temperature; and under different stress states. The reservoir-forming rock can have different textures such as shaley and silty unconsolidated sandstones or clean-cemented sandstones. These different rocks produce gas at low rates. Tight reservoir rocks can be blanket or lenticular, homogeneous or heterogeneous, and can contain a single layer or multiple layers, be fractured or unfractured, and mainly produce dry natural gas.

A COLUMN ON THE HISTORY AND CULTURE OF GEOPHYSICS AND SCIENCE IN GENERAL

De Rerum Fractura. These days it is much in the mind of petroleum seismic researchers to get into the “fracture game.” This is driven by the remarkable rise in natural gas reserves from shale reservoirs, primarily in the US for now but quickly being exported worldwide. Shale formations have long been of interest as source rock and reservoir seal, but in the last 20 years shale has taken center stage as a reservoir in its own right. Gone are the days when we would drill through shale and get a gas kick, ignore it, then drill on down to conventional reservoirs. Gas shale is considered an unconventional reservoir, mainly because of very low porosity and permeability compared to those Swiss cheese sandstones and limestones. For a 25% porosity conventional reservoir, you need only to punch a hole through it, open the choke, and production will scream out for decades. But shale, like tight gas sand, must be modified to open channels for production. Wells must be horizontally drilled to expose more reservoir rock and they must be fractured.

Technology Focus: Tight Reservoirs (October 2010)

Technology Focus Shale-gas reservoirs are becoming an increasingly significant percentage of the global tight-reservoir landscape. Three questions reflect this increasing dominance but are applicable overall to tight formations. Is the long multistage-fractured horizontal well into which millions of gallons of water are pumped downhole with only a third of the contacted reservoir propped open the most efficient way to produce the reservoir? Is the long multistage-fractured horizontal well the endgame solution to Master’s Resource Triangle? If the equations set forth by Darcy and Young/Laplace are valid, does contacting a large amount of the formation with only water constitute stimulation of the reservoir? Capillary pressure is significant in tight reservoirs. Stimulation-fluid invasion into smaller pore diameters and invasion of proppant-free stimulation fluid into both induced fractures and dilated natural fractures will have an effect. Production-decline rates and long-term health of wells (improved fluid flow or degree of formation damage) in tight reservoirs will depend on how capillary forces are managed in the reservoir. Log-normal large volumes of hydrocarbon found in tight reservoirs are difficult to develop because of constrained drainage areas, complicated petrophysics, lithology, and formation heterogeneity. These difficulties, complexities, and heterogeneities dictate planning of drilling, completion, and stimulation specific to the well in question. They also dictate continued advances in knowledge and technology if the majority of the hydrocarbon asset is to be produced effectively. Early production levels will be dependent on the length of propped fracture from the wellbore that has actually cleaned up and this contributing to hydro-carbon flow. Our industry needs to make advances in: real-time measurement; post-fracture monitoring with production analysis; identifying sweet spots, then placing perforations to create complex conductive fractures; innovative proppants and proppant-placement techniques in primary and complex fracture geometries; fluid recovery; formation-damage control and permeability enhancement; proppant transport with less-damaging stimulation fluids; and environmentally responsible drilling, completion, and production services. Tight Reservoirs additional reading available at OnePetro: www.onepetro.org SPE 128191 • “Selecting Drilling Technologies and Methods for Tight Gas Sand Reservoirs,” by Pilisi, N., SPE, Blade Energy Partners, et al. SPE 131778 • “Using Microseisms to Monitor Hydraulic Fractures in the Bakken Formation of North Dakota,” by Gary S. Forrest, Schlumberger, et al. SPE 130043 • “Fracturing Design Aimed at Enhancing Fracture Complexity,” by M.Y. Soliman, Halliburton, et al.

Effect of Fracture Dip and Fracture Tortuosity on Petrophysical Evaluation of Naturally Fractured Reservoirs

Summary A model is developed for petrophysical evaluation of naturally fractured reservoirs where dip of fractures ranges between zero and 90°, and where fracture tortuosity is greater than 1.0. This results in an intrinsic porosity exponent of fractures (mf) that is larger than 1.0. The finding has direct application in the evaluation of fractured reservoirs and tight gas sands, where fracture dip can be determined, for example, from image logs. In the past, a fracture-matrix system has been represented by a dual-porosity model which can be simulated as a series-resistance network or with the use of effective medium theory. For many cases both approaches provide similar results. The model developed in this study leads to the observation that including fracture dip and tortuosity in the petrophysical analysis can generate significant changes in the dual-porosity exponent (m) of the composite system of matrix and fractures. It is concluded that not taking fracture dip and tortuosity into consideration can lead to significant errors in the calculation of water saturation. The use of the model is illustrated with examples.

A Method for Estimating Hydrocarbon Cumulative Production Distribution of Individual Wells in Naturally Fractured Carbonates, Sandstones, Shale Gas, Coalbed Methane and Tight Gas Formations

Summary A method, based on factual observations of naturally fractured reservoirs in several countries, is presented for estimating distribution of hydrocarbon cumulative production in wells drilled in fractured reservoirs of Types A, B or C. These observations indicate that in reservoirs of Type C, most of the cumulative production is provided by just a few wells, while the majority of the wells contribute a small part of the reservoir cumulative production. In reservoirs of Type B, the number of wells contributing significantly to cumulative production becomes larger relative to the case of Type C reservoirs. Finally, in reservoirs of Type A, a large number of wells contribute to field production, as compared with Type B reservoirs. The method is shown to be useful for tackling problems of practical importance in naturally fractured reservoirs, including performing or not performing infill drilling, estimating the variation in cumulative hydrocarbon production per well in a given reservoir and estimating the number of wells that might be required for a given field hydrocarbon recovery. The method is illustrated using data from various fractured reservoirs, including the Barnett shale and sandstone reservoirs in the United States, carbonate reservoirs in Mexico and Venezuela and coalbed methane reservoirs and tight gas sands in Canada.